Hydrocarbon recovery

ABSTRACT

A thermal hydrocarbon recovery apparatus comprises: a plurality of steam injector tubes each provided with a plurality of injector autonomous inflow control devices, AICDs, spaced apart from each other along the length of each steam injector tube; a plurality of production tubes each provided with a plurality of production autonomous inflow control devices, AICDs, spaced apart from each other along the length of each production tube; wherein said injector AICDs are arranged to inject steam into a geological formation so as to reduce the viscosity of hydrocarbons in the formation; and wherein said production AICDs are arranged to permit the flow of heated hydrocarbons into said production tubes for movement to the surface.

The present invention relates to a thermal hydrocarbon recovery apparatus and an associated method. In particular, but not exclusively, the invention relates to thermal hydrocarbon recovery by steam injection.

In various locations around the world, significant hydrocarbon reserves are known to be present in the Earth's subsurface in oil or tar sands. The hydrocarbons found in these settings take the form of bitumen or heavy crude oil which is particularly dense and viscous and does not flow naturally. In geological settings where lighter hydrocarbons are present, a well can be drilled into a hydrocarbon bearing formation and hydrocarbons such as petroleum and gas will readily flow from the hydrocarbon-bearing geological formation through the well to the Earth's surface due to higher pressures of the formation compared with the Earth's surface.

The viscous bitumen and heavy crude oil is more difficult to extract, although it is possible to do this using thermal hydrocarbon recovery techniques. The key principle of thermal recovery is to heat up the oil sands so that the bitumen or heavy oil becomes sufficiently viscous that it will flow, allowing it then to be extracted from the formation in its heated and flowable condition.

One technique for doing this involves drilling a well and then injecting steam through the wellbore into the formation to heat up the formation and the heavy oil. Thereafter, the oil is extracted through the wellbore to the surface. Several cycles of heating and extraction would typically be carried out. The method typically uses a single wellbore both for injecting the steam and for extracting and moving the oil to the surface, and is known as a “huff and puff” system.

Another known thermal recovery technique is steam assisted gravity drainage (SAGD). This technique also works on the basis of injecting steam into the formation, although it makes use of separate wellbores; a designated “steam injector wellbore” for injecting the steam and another “producer wellbore” for extracting or producing the oil to the surface. Typically, horizontal sections of the steam injector wellbore and the production wellbore run near to each other in pairs with the steam injector wellbore located above the producer wellbore.

As steam is injected into the formation through the injector wellbore, a steam heated region of the formation above and around the injector wellbore is formed, known as a steam “chamber”. This causes the heavy oil to heat up and drain downwards under gravity towards the producer wellbore that has been warmed up during initial circulation. The drainage of oil allows the steam to rise up further through the steam chamber toward its periphery enabling continuous growth of the steam chamber. After releasing its heat energy the steam then condenses and flows downwards together with the mobile oil under the influence of gravity to the producing wellbore beneath.

Typically, the injector and producer wellbores comprise horizontal sections that run roughly parallel and horizontally in the geological formation and are spaced a few metres apart from each other with the injector wellbore located above the producer wellbore, for example by a spacing of around 5 m.

Although the present SAGD technique has benefits in terms of efficiency and oil recovery rates, there are a number of problems associated with the SAGD technique as used today. For example, it can be difficult to control steam breakthrough in the producer wellbore and to achieve precise ‘distribution’ of steam along the horizontal injector so that an optimal steam chamber can be formed.

In order to extract oil consistently via the producer wellbore, it is ensured that a layer, trap or sump of condensed water and the hydrocarbons sought to be extracted is maintained around the producer wellbore such that steam from the injector wellbore cannot “short circuit” and break through directly to the producer wellbore section. However, steam breakthrough may occur if the heating conditions and steam chamber is not correctly established. For example, the temperature in the geological formation around the producer wellbore should be less than that of the steam chamber (sub-cool) for oil to drain downwards into the producer wellbore. If not, steam may replace the oil and the condensed water at the producer well, which is undesirable as it delays production of hydrocarbons and causes damage to the lift pumps located in the producer wellbore for pumping the oil to the surface. Various steps then need to be taken to rectify the situation.

In order to avoid steam breakthrough from occurring, various measures may need to be taken. In particular, the production rate may need to be limited to maintain the mobile hydrocarbon layer in the present SAGD technique. This may be done for example by controlling the lift pump operating inside the production pipe to control drawdown pressure in the tubing or by reducing the steam injection from the injector wellbore. Temperature also needs to be controlled to maintain a fluid trap around the producer tubing. Specifically, the temperature in the region around the producer wellbore has to be kept cooler than the steam chamber temperature, i.e. “sub-cool”, in order for a suitable fluid trap to build up and be maintained.

Although still viscous enough to flow, the fluid to be extracted around the producer wellbore is comparatively viscous which limits extraction efficiency. It is therefore generally desirable that the steam chamber extends as close as possible to the producer wellbore to keep the fluid as mobile as possible without causing steam breakthrough. A balance needs to be kept and with this in mind, present methods are based on a stand off distance between he steam injection and the production wellbore of between around 4 and 6 m in order to help keep temperature conditions and the “steam chamber” stable and relatively predictable near the producer wellbore. Again, adjustment of production or injection rates may be required to maintain temperature conditions. Using present methods therefore, it can be difficult to consistently achieve commercial production rates of heavy oil as the entire well has to be choked back even with localised steam break through.

Existing techniques have focused on tackling the above described issues of steam breakthough using inflow control devices ICDs with a fixed flow path construction. Known generally as channel or nozzle type ICDs, these are disposed on the production tubing or liner to provide fluid connection between the tubing interiors and the geological formation in specific locations along the tubing sections. Such ICDs in the producer tubing impose an additional pressure drop between the formation and the tubing to hinder steam breakthrough and to maintain the fluid trap around the tubing. Nevertheless, avoiding steam breakthrough and forming a suitable sub-cool trap around the producer tubing are significant challenges associated with present thermal recovery techniques.

There are also considerations in relation to how the injector well operates. As mentioned above, it is desired to be able to create a suitable steam chamber and distribute steam in a controlled manner. However, it is also important to be able to do so along the entire length of the wellbores. This again helps to reduce the risk of steam breakthrough to the production well and more crucially to avoid localised and unbalanced steam chamber development.

For injector wells, a wellbore hydraulic effect occurs, which limits the length of horizontal tubing usable in the SAGD. In turn, this means that numerous wells typically need to be drilled to provide the necessary coverage to thermally recover heavy oil from a given region. Typically, the maximum length of a horizontal section for SAGD is around 500-1000 m. This is because the amount of steam entering the geological formation (exiting the wellbore) and the amount continuing further downstream inside the wellbore is significantly dependent on the localised pressure balance, as shown in

FIG. 2. At positions earlier along the tubing, there will be delivered generally higher flow rates at the “heel” section (toward the wellhead end of the horizontal wellbore section) whilst the differential pressure and flow rates at locations successively further away from the pressure source will gradually diminish (due to a reduced fluid volume in the tubing). The common practice to address such issues of wellbore hydraulics is to install two horizontal injection tubing sections of different length, one above the other (dual tubing completion). Typically, the two injection tubing sections are run in the same injection wellbore, as shown in FIG. 2. The injection tubing sections are placed in an overlapping configuration relative to each other so as to reduce the overall pressure variability along the wellbore as seen by comparing FIGS. 2 a and 2 b. It can be seen that a moderately uniform pressure/flow rate distribution can be achieved along the length of the tubing, but it can also be seen that the effectiveness of this technique requires a certain proximity between the end of the upper injector (at the “heel” of the wellbore and commonly referred as the short string) and the end of the lower injector tubing (at the “toe” of the wellbore and commonly referred as the long string). This means that the required steam chamber conditions may still only be provided for a relatively limited length of tubing, as defined between the two injector tubing ends.

Attempts have been made to tackle the issues of wellbore hydraulics and uneven steam chamber growth by using fixed flow path inflow control devices ICDs. These are fitted in the injector wellbore and are disposed on the tubing or the liner to provide fluid connection between the respective tubing interiors and the geological formation in specific locations along the tubing sections. In the injector tubing, the ICDs provide an outlet for the steam into the formation. In order to inject steam into the formation, the injector tubing is pressurised to a pressure above the formation pressure, and steam can thereby be forced through the ICDs. Several ICDs are provided along the length of the tubing allowing steam to be injected at specific locations along the tubing providing high steam injectivity at those locations. Using ICDs in the injector tubing imposes an additional pressure drop between the tubing and the formation. This enables more steam, which would otherwise ‘leak off’ into a receptive formation, to be channeled along the injection wellbore through a horizontal section of the wellbore. However, a problem associated with using these ICDs in the injector tubing is that the steam flow rate is driven by the pressure differential, as seen in FIG. 1. Since formation pressure varies somewhat along the length of the tubing and over time, a change in the pressure differential can be caused and then, due to the sensitivity of flow rate to a change in the pressure differential, it can be hard therefore to control the desired steam rates so as to form a suitable steam chamber.

In one form therefore, the technique has been adapted to make use of the critical flow rate for fixed flow path orifice/channel and nozzle ICDs, which is a predictable, constant flow rate known occur at the speed of sound. In these devices, the steam injection rate is up to a point dependent on the pressure differential but at this critical flow rate, the steam injection flow rate cannot be increased any further, even if the pressure differential is made larger. A drawback is that this requires a pressure differential to be generated in the tubing of approximately twice the formation pressure in order to create this effect using conventional tubing and ICD arrangements. Since the need of doubling the pressure differential also applies at the toe section, which is furthest away, it will require significantly higher overall steam pressure at the wellhead. Injection into the formation in this critical flow mode requires therefore an undesirably large amount of energy, and the high speed of the fluid can impart significant erosion and damage to the equipment. In addition, the steam exiting the ICDs is typically turbulent and may require additional diffusers in order to harness and direct the flow of steam into the formation as required. The use of diffusers also causes dissipation of energy from the flow. These are undesirable effects even though such devices can yield a predictable flow rate.

Accordingly, there are a number of difficulties associated with existing techniques of thermal recovery, including for example how to distribute steam uniformly, how to target steam distribution to mitigate the impact of geological heterogeneity, and/or how to target steam distribution for optimal steam chamber growth. An additional challenge is to avoid excessive steam injection.

In a first broad form the invention may be defined by the following paragraphs.

The invention may provide thermal hydrocarbon recovery apparatus comprising at least one flow control device for autonomously adjusting a flow of fluid through the flow control device, the at least one flow control device provided to a tubing for location in a wellbore, the flow control device being arranged to fluidly connect a geological formation with an inside of the tubing, and wherein the tubing is further arranged for at least one of: injecting steam into the geological formation for heating hydrocarbons; and moving steam heated hydrocarbons from the geological formation to the surface.

The apparatus may comprise a first, injector tubing for injecting steam into the geological formation for heating hydrocarbons, and a second, producer tubing for moving steam heated hydrocarbons from the geological formation to the surface, wherein the at least one flow control device may be provided to at least one of the injector tubing and the producer tubing. At least one flow control device may be provided to each of the injector tubing and the producer tubing.

The producer tubing may be provided with at least one flow control device configured to autonomously permit flow of heated oil and water but restrict flow of steam through the flow control device from the formation. The producer tubing may be provided with a plurality of said flow control devices spaced apart from each other along a length of the tubing.

The injector tubing may be provided with a plurality of said flow control devices spaced apart from each other along a length of the injector tubing, wherein each flow control device may be configured to permit flow of steam through the control device at a predetermined flow rate. The flow control devices may be arranged to produce a predetermined profile of steam injectivity along a length of the injector tubing.

Different flow control devices may be configured to produce substantially the same steam flow rate. The flow control devices may be configured to permit flow of steam therethrough at a substantially constant flow rate, where the steam in the injector tubing is pressurised sufficiently.

The injector tubing may comprise an injector tubing section arranged to extend substantially horizontally and in spaced parallel relationship with a producer tubing section of the producer tubing. The injector tubing and producer tubing may be spaced apart from one another by a distance of less than 5 m, less than 4 m, less than 3 m, less than 2 m and/or less than 1 m. For example, they may be spaced apart by a distance of between around 1 and 2 m.

The injector tubing may comprise a plurality of steam injector tubing sections arranged to be located within respective substantially horizontal wellbore sections, and a connecting injector tubing section which is arranged to extend between a surface well head and a subsurface location for fluidly connecting each of the plurality of steam injector tubing sections with the surface well head.

The producer tubing may comprise a plurality of producer injector tubing sections arranged to be located within respective substantially horizontal wellbore sections, and a connecting producer tubing section which is arranged to extend between a surface well head and a subsurface location for fluidly connecting each of the plurality of producer injector tubing sections with the surface well head.

The geological formation may be an oil sand and the hydrocarbons to be recovered may be viscous hydrocarbons.

The apparatus may take the form of a steam assisted gravity drainage system.

The invention may also provide use of an autonomously adjustable flow control device in a thermal oil recovery system in which steam is injected into a geological formation to heat hydrocarbons and the steam-heated hydrocarbons are moved from the geological formation to the surface.

The use may provide the effect of discriminating against steam inflow into a tubing of the recovery system which tubing may be arranged for moving hydrocarbons from the hydrocarbon formation to the surface. The use may provide the effect of controlling the formation of a steam chamber to safeguard against steam breakthrough and/or provide the effect of assured recovery of oil under steam breakthrough conditions.

The use may include any features of the apparatus defined above, where appropriate.

The invention may also provide a method of thermal recovery of hydrocarbons from a geological formation, the method comprising the steps of:

-   a. providing at least one flow control device to a tubing, the flow     control device arranged to autonomously adjust a flow of fluid     through the flow control device; -   b. locating the tubing in a wellbore, by which the at least one flow     control device is arranged to fluidly connect the geological     formation and an inside of the tubing; and -   c. injecting steam into the geological formation to heat the     hydrocarbons; -   d. moving the steam heated hydrocarbons from the geological     formation to the surface; and -   e. using the tubing for carrying out at least one of the steps c and     d.

The method may be a method of assured recovery, or production, of oil under steam breakthrough conditions. Thus, it may safeguard production and prevent damage to equipment even if steam is present against the outer surface of a producer tubing. It may also be a method of controlling steam chamber formation.

The method may use any features of the apparatus defined above, where appropriate.

In a second form the invention may be defined by the following numbered paragraphs:

1. A thermal hydrocarbon recovery apparatus comprising:

-   -   a plurality of steam injector tubes each provided with a         plurality of injector autonomous inflow control devices, AICDs,         spaced apart from each other along the length of each steam         injector tube;     -   a plurality of production tubes each provided with a plurality         of production autonomous inflow control devices, AICDs, spaced         apart from each other along the length of each production tube;     -   wherein said injector AICDs are arranged to inject steam into a         geological formation so as to reduce the viscosity of         hydrocarbons in the formation;     -   and wherein said production AICDs are arranged to permit the         flow of heated hydrocarbons into said production tubes for         movement to the surface.

2. Apparatus as defined in paragraph 1, wherein at least one injector AICD is configured to permit the flow of steam through the injector AICD at a substantially constant flow rate, once a pressure differential across the injector AICD exceeds a threshold value.

3. Apparatus as defined in paragraph 2, wherein said substantially constant flow rate varies over time by less than 10% of a mean value.

4. Apparatus as defined in paragraph 2 or 3, wherein for steam in the temperature range between 150 and 160 degrees centigrade, said substantially constant flow rate has a mean value of between 0.3 and 10 m³/hr.

5. Apparatus as defined in paragraph 2, 3 or 4, wherein for steam in the temperature range between 150 and 160 degrees centigrade, said threshold value is a value between 8 kPa and 12 kPa.

6. Apparatus as defined in any preceding paragraph, wherein at least one production AICD is configured to permit flow of heated hydrocarbons and condensed water into a production tube but to restrict the flow of steam into the production tube.

7. Apparatus as defined in paragraph 6, wherein said at least one production AICD is configured so that in the event of steam from said steam injector tubes reaching the production AICD, the production AICD autonomously closes so that any steam entering the production tube via the production AICD is less than 5% by weight of the total fluid entering the production tube via the production AICD.

8. An apparatus as defined in any preceding paragraph, wherein at least some of said injector AICDs comprise a body defining a flow path through the AICD and defining a recess containing a movable valve body, arranged so that movement of fluid along said flow path causes the valve body to move by exploiting the Bernoulli effect thus controlling the flow of fluid along said flow path.

9. An apparatus as defined in any preceding paragraph, wherein at least some of said production AICDs comprise a body defining a flow path through the AICD and defining a recess containing a movable valve body, arranged so that movement of fluid along said flow path causes the valve body to move by exploiting the Bernoulli effect thus controlling the flow of fluid along said flow path.

10. An apparatus as defined in paragraph 8 or 9, wherein said valve body is a freely movable valve body.

11. An apparatus as defined in any preceding paragraph, wherein the injector AICDs of at least one of the steam injector tubes are configured to inject steam into said formation at substantially the same steam flow rate.

12. An apparatus as defined in any preceding paragraph, wherein the injector AICDs of at least one of the steam injector tubes are configured to inject steam into said formation at different steam flow rates so that appropriate flow rates can be used for different parts of said formation.

13. An apparatus as defined in any preceding paragraph, wherein said steam injector tubes are arranged to extend substantially horizontally.

14. An apparatus as defined in any preceding paragraph, wherein said production tubes are arranged to extend substantially horizontally.

15. An apparatus as defined in any preceding paragraph, wherein said geological formation is an oil sand.

16. An apparatus as defined in any preceding paragraph, wherein said hydrocarbons to be recovered are bitumen or heavy oil.

17. An apparatus as defined in any preceding paragraph, taking the form of a steam assisted gravity drainage, SAGD, system.

18. A method for thermal recovery of hydrocarbons from a geological formation, the method comprising the steps of:

-   -   a) providing a thermal hydrocarbon recovery apparatus as defined         in any preceding paragraph;     -   b) injecting steam into said geological formation via said         injector AICDs;     -   c) collecting heated hydrocarbons in said production tubes via         said production AICDs; and     -   d) moving said hydrocarbons to the surface via said production         tubes.

There will now be described, by way of example only, embodiments of the invention with reference to the accompanying drawings, of which:

FIG. 1 is a plot showing the relationship of differential pressure versus flow rate for a prior art fixed construction nozzle/orifice or channel based ICD;

FIG. 2 is a schematic representation of a prior art injection wellbore with dual tubing completion for steam injection;

FIGS. 3A and 3B provide perspective and end on representations of a region of the earth's subsurface containing a thermal hydrocarbon recovery apparatus according to the present invention;

FIG. 4A is a plot of prior art fixed construction ICD performance curves for gas/steam, water and oil;

FIG. 4B is a plot of performance curves for gas/steam, water and oil for the AICDs used in embodiments of the present invention;

FIGS. 5A and 5B are schematic cross-sectional representations showing a steam breakthrough scenario in the vicinity of a producer tubing;

FIG. 6 is a graph showing the behaviour of operating behaviour for AICDs used in an injector tubing; and

FIG. 7 is a schematic representation of an arrangement of pipe sections for thermal recovery from a geological formation.

With reference firstly to FIGS. 3A and 3B, there is shown a process for thermally recovering hydrocarbons from an oil sand by steam assisted gravity drainage (SAGD). The present examples are described particularly with reference to the SAGD method, but it will be appreciated that the invention described herein is equally applicable to other steam assisted thermal recovery methods including for example the single tubing cyclical “huff and puff” method mentioned above or non-cyclic continuous steam drive systems or the like.

In FIGS. 3A and 3B, a section of the Earth's subsurface is shown with an oil sand formation 12 located at depth. An injection well 14 and a production well 16 are provided one above the other comprising horizontal injector and producer tubing sections 14 h,16 h, separated by a vertical spacing of around 5 m. Injection of steam from the injector tubing section 14 h generates a mushroom shaped heated region or “steam chamber” 18 in the oil sand layer above and around the wellbore section 14 h. After an initial warm up period a convection process is initiated by which bitumen or heavy oil in the oil sand is heated and drains downwards whilst the steam rises through the steam chamber. As it reaches a cooler outer area of the chamber the steam condenses. The heated bitumen becomes mobile and drains downward together with condensed water as indicated by arrows 18 a. At the producer tubing section 16 h below, the bitumen or heavy oil is flowable and is drawn into the producer tubing under formation pressure and/or with assistance of a production lift pump (not shown) inside the production tubing section 16 h by which the mobilised bitumen or heavy oil together with the condensed water is returned to the surface production well head 19.

In the present invention, the injector tubing section 14 h and the producer tubing section 16 h are both fitted with multiple flow control devices 14 f, 16 f in the wall of the tubing sections and are spaced apart from each other along the length of the respective tubing sections. The tubing referred to here can be a liner or sand screen (in direct contact with the geological formation) or an internal tubing that locates inside the liner/screen. These devices provide fluid connection and passage between the geological formation 12 and the interiors of the production and injection tubing sections 14 h, 16 h. The flow control devices in this example are so-called autonomous inflow control devices (AICDs). These devices comprise a housing and a “floating disc” inside the housing to define a flow path for fluid through the valve. Importantly, the floating disc creates a flow restriction. However, the disc is movable within the housing to alter the flow path restriction.

The AICDs provide two particular effects, which contribute to the production of hydrocarbon and the injection of steam. Firstly, the disc moves in response to the stagnation pressure and the velocity of fluid. This means that it autonomously adjusts its position and flow path to conserve energy, following the principles of Bernoulli's equation. Thus, for a given pressure differential between the inside of the tubing and the geological formation, the flow can be choked or shut off altogether when a lower viscosity fluid is encountered at the restriction, and as the disc moves to close the flow path due to low pressure. The disc movement is caused by high stagnation pressure on one side and faster flowing low viscosity fluid that creates a lower dynamic pressure on the other.

Secondly, when the autonomous valve is subjected to single-phase flow such as steam the floating disc will remain open, whilst its position within the housing is balanced by the stagnation pressure created at the back of the disc and the flowing “dynamic” pressure formed at the front of the disc. The higher the flow rate, as induced by a larger differential pressure across the valve, the dynamic flowing pressure at the front of the disc becomes lower. This pulls the disc closer to its ‘SHUT’ position and reducing the flow rate automatically. Effectively the autonomous valve will yield an “almost” constant flow rate once a threshold maximum differential pressure is reached.

Flow control devices that operate based on these or closely similar principles are described in WO2008/004875, WO2009/088292 and WO2009/113870 and relevant parts of the disclosures of those documents are incorporated herein by reference.

The flow valves for the production tubing section 16 h for the present SAGD system makes use of the first of these operating principles, as can be seen with reference firstly to FIGS. 4A and 4B. In FIG. 4B, there is shown a plot 20 of differential pressure (between the wellbore formation and the drawdown pressure in the tubing) against flow rate for the AICDs used in the production tubing section. The plot 20 displays performance graphs for water 20 a, oil 20 b, and gas/steam 20 c showing the flow rate behaviour through the valve. All of the curves 20 a-20 c show a rapid increase in differential pressure whilst flow rate increases. In contrast in FIG. 4A, the corresponding performance using fixed construction nozzle/orifice prior art ICDs can be seen in the curves 22 a-22 c of plot 22, plotted at the same scale. These show only a very gradual increase of differential pressure, particularly in the gas curve 22 c. As can be seen from the plot 20 for the AICD, the ‘gas/steam’ flow is choked back and significantly limited due to the movement of the floating disc.

The AICDs 16 f in the producer tubing 16 h are designed to discriminate against the steam based on the autonomous adjustability of the AICDs. The AICD is designed to permit flow of heated oil or liquid bitumen and condensed water through the AICD, but prevent steam flow. Should any steam break through to the production tubing section, flow of steam through the AICD will be blocked off or choked since the viscosity of the steam is significantly lower than that of the liquid oil or bitumen or water, which causes the floating disc of the AICD to restrict the flow path in the valve. The stagnation pressure then keeps the valve ‘SHUT’ until steam is replaced by oil or liquid flow. As a result, the risk of drawing steam into the production well bore is greatly reduced. Damage to the lift pump by steam is avoided whilst there is adequate inflow of oil and water through the AICDs in the rest of the wellbore to meet the withdrawal rate of the pump.

As illustrated in FIGS. 5A and 5B, the fluid discrimination and shut off functionality of the AICD is shown. In FIG. 5A, the production tubing section 14 h is shown with the AICD 14 f provided in a wall of the section 14 h. A layer of molten liquid bitumen plus water 18 t drained from the steam chamber 18 lies along and around an outer surface of the production tubing section 14 h, and is presented to the AICD. Flow is permitted through the AICD and into the producer tubing to the well head as indicated. In FIG. 5B, a steam breakthrough scenario is illustrated, and the AICD has blocked off the steam due to its sensitivity and discrimination against low viscosity steam. The remaining parts of the producer tubing, equipped also with AICDs, will continue to produce the bitumen and water unhindered until they are ‘SHUT’ by the encroaching steam. Preferably the AICDs ensure that any steam entering the production tube is less than 5% by weight of the total fluid entering the production tube.

Thus, steam is drawn close to but not through the production tubing, so as to operate effectively at “zero-subcool”. This improves the overall thermal recovery process, firstly because the steam injection can be performed more ‘aggressively’ without the fear of the steam short-circuiting into the production well below. More heat energy can be used to facilitate the steam chamber growth and accelerate the recovery of oil. Secondly, since the steam chamber extends to the close vicinity of the producer tubing instead of being shielded by an overlying liquid trap that has to be kept cooler (subcool), a warmer and hence a more effective drainage process takes place in this critical near well bore region. The autonomous discrimination against steam flow is also beneficial in terms of the entire ‘horizontal’ section of the production well regardless of the elevation of the well trajectory. For example, when the producer tubing sections are present at different elevations, sections at a higher elevation may have steam drawn into it initially, at which point the AICDs close momentarily and temporarily until water and molten oil build up again and they re-open. At the same time, sections at other elevations may follow a different open-close cycle and the AICDs will open and close in response to steam being drawn into those other sections at different times.

Turning now to consider the injection tubing with reference to FIG. 6, the graph 30 shows a characteristic performance curve 32 for the AICD, which indicates a rapidly increased flow rate for increased differential pressure. However, above a lower threshold differential value 34 a, the flow rate no longer changes significantly which means that provided the pressure differential is somewhere above the threshold, a stable flow rate into the formation is achieved. In practice therefore, a constant flow rate of steam is selected and applied under pressure into the injection tubing to ensure that the pressure differential across the AICD is above the threshold 34 a. The injection pressure is applied to the tubing at a fixed output level, sufficiently above the threshold 34 a to account for and reduce sensitivity to possible variations in pressure in the formation, which may impact on the pressure differential. Ideally, the threshold 34 a represents the minimum differential pressure that is required for the AICD located furthest away from the wellhead. There is defined therefore an operating region 36 of pressure differentials which ensures flow through the AICD at the maximum and ‘near constant’ flow rate. This may be defined based on expected variations in differential pressure for a given hydrocarbon reservoir scenario. This can also be defined based on the total length of the injection tubing, either in a single or ‘multi-branch’ configuration. In general, each AICD may be configured differently depending on its position within the system. The operating region extends to an upper threshold pressure differential 34 b. It might be possible to generate pressure at significantly higher differentials, above an upper threshold value 34 b but it is typically unnecessary to design the steam injection system in this way since by operating at a fixed output level in the operating region 36, a constant maximum flow rate is achievable already.

Preferably the steam flow rate for each AICD varies over time by less than 10% of a mean value. The physical properties of steam, e.g. density, vary with temperature. For steam in the temperature range 150-160 degrees C., a typical mean steam flow rate may be between 0.3 and 10 m³/hr, or between 0.7 and 0.9 m³/hr, and the threshold value 34 a may be between 8 and 12 kPa. The range values quoted here are for steam around a mean temperature of 155 degrees C., and for the same AICD these range values will be different at, say 230 degrees C. The appropriate steam temperature is chosen in the field.

In addition, there will be the situation when we need to ‘target’ the steam distribution at different horizontal locations. Each AICD will have a ‘near constant’ flow rate, but one location may require 2 to 10 times more steam than another location, for example.

It is desirable to raise the injection pressure inside the injector tubing as high as possible. The higher injection pressure, whilst producing negligible impact on the injection rate near the heel of the well bore 14, allows more steam to be pushed forwards and further downstream towards the toe of the wellbore. This means that a single, smaller injection tubing can be installed and/or that a longer injection well, and/or that multiple horizontal branches can be constructed leading to significant saving in capital costs. Raising the injection pressure will affect the steam temperature (higher). This may affect the uniformity of the steam chamber with higher injection temperature near the heel. However, the uneven heat input to the formation can be compensated by appropriately sizing the AICDs and modifying the population of such devices along the well bore.

The AICDs in the injector tubing 14 h are preferably individually designed so that each AICD outputs a specific (same or different) flow rate according to the need for growing the steam chamber. This may be carried out by adjusting the sensitivities of the AICDs so that different pressure differentials in different AICDs produce the respective maximum flow rates. Producing a specific ‘near constant’ maximum flow rate at each AICD along the injector tubing also means that steam can be targeted more precisely along the horizontal well, for example evenly for homogeneous sand producing a relatively flat injectivity profile along the length of the wellbore section or specifically distributed to compensate for the heterogeneity in reservoirs with other lithologies. Either way, growth of the steam chamber can be optimised by specifying particular AICD designs for different positions. The AICD design for the injector tubing takes into account that pressure in the steam injector tubing is higher at an upstream end, and that fluid which is not passed into one AICD flows to successive AICDs downstream, resulting in a reduced pressure in the tubing and therefore a reduced differential pressure across each AICD. The AICD are designed therefore to have a flow rate behaviour such that a maximum and “near constant” flow rate can be generated for the expected differential pressure for the particular AICD along the tubing. The size, dimensions and/or materials may be selected to provide the desired flow behaviour, and this could apply also to the producer tubing. For example, the size and dimensions or scale of the AICDs in different positions along the tubing may be different in order to produce different flow rate responses when subjected to a pressure differential. This constant flow rate behaviour is achieved at relatively low differential pressures, in contrast to the previously used flow devices that relied on achieving critical flow.

In the presently described system using AICDs in both the injection and production wells, it is less critical to provide exact stand-off (currently 5 m) between the injector pipe sections and producer pipe sections in order to control the steam chamber and avoid steam break through to the production tubing. It may therefore be feasible to use stand-off distances of for example 2 to 3 m. In addition, control of distribution of steam from the injector tubing is significantly improved and is no longer sensitive to formation pressure variations along its length. The pressure needed to deliver a predetermined rate of steam is much less than double the formation pressure as with existing methods and injectivity is dependent on deliverability of the steam within the injector tubing rather than by variations in the reservoir. Accordingly, dual “toe and “heel” injector pipes are not required, and limitations on the length of horizontal tubing sections are greatly removed. This gives a significantly greater freedom of design of an SAGD or similar system for extracting heavy oils from oil sands. Tubing sections may be extended further and tubing configurations as shown in FIG. 7 can be deployed to give improved and more cost effective coverage. Constant steam injection rates can be applied to the entire length without the risk of over-injection at locations which can yield abnormal steam chamber development, e.g., ‘dog-bone’ shape. In the producer tubing sections the possibility of steam breakthrough and inflow of steam into the production tubing is greatly reduced.

In FIG. 7, a system for thermal recovery of hydrocarbons from a large geographical region is shown in which the producer and injector tubing sections are provided with AICDs. FIG. 7 shows generally an SAGD arrangement 40 which has a plurality of horizontal injection tubing sections 40 s extending away in opposing directions from a joining pipe section 40 j which is also a horizontal tubing section connecting the horizontal sections 40 s. The joining pipe section 40 j is then connected to a well head at the Earth's surface via a single vertical section 40 v.

The arrangement 40 also includes a plurality of horizontal producer tubing sections 40 p arranged in a similar way and connected to the surface well head via a single vertical section 40 w. The steam injection sections 40 s are located above the production sections 40 p to provide the steam assisted drainage required.

This arrangement is a significant improvement on existing wells where the required close control of the production pump and steam supply dictated that each horizontal section be accompanied with a vertical section to the relevant well head. Accordingly, the present invention helps to reduce the infrastructure costs and overall rate of recovery from oil sands. The impact to the environment can be greatly improved by minimising the surface footprint with much reduced number of wellhead and associated equipment.

The present description has referred generally to sections of producer tubing and injector tubing and it will be understood that these tubings are located, in use, in production and injection wellbores of the production and injection wells. It will be appreciated that the producer and/or injector tubing may take the form of a wellbore liner or sandscreen or the like and that the AICDs may be fitted to the liner and/or sandscreen. It will also be appreciated that the producer tubing and/or injector tubing may take the form of a separate production pipe and/or injector pipe located, in use, within wellbores provided with a liner and/or sandscreen or the like, and that the AICDs may be fitted to the separate production and/or injector pipe. In a variant, the AICD itself may be fitted with a mesh or the like or be otherwise arranged to shut out and prevent inflow of sand or other particles from the formation.

Various modifications and improvements may be made within the scope of the invention herein described. 

1.-18. (canceled)
 19. A thermal hydrocarbon recovery apparatus comprising: a plurality of steam injector tubes each provided with a plurality of injector autonomous inflow control devices, AICDs, spaced apart from each other along the length of each steam injector tube; a plurality of production tubes each provided with a plurality of production autonomous inflow control devices, AICDs, spaced apart from each other along the length of each production tube; wherein said injector AICDs are arranged to inject steam into a geological formation so as to reduce the viscosity of hydrocarbons in the formation; and wherein said production AICDs are arranged to permit the flow of heated hydrocarbons into said production tubes for movement to the surface.
 20. Apparatus as claimed in claim 19, wherein at least one injector AICD is configured to permit the flow of steam through the injector AICD at a substantially constant flow rate, once a pressure differential across the injector AICD exceeds a threshold value.
 21. Apparatus as claimed in claim 20, wherein said substantially constant flow rate varies over time by less than 10% of a mean value.
 22. Apparatus as claimed in claim 20, wherein for steam in the temperature range between 150 and 160 degrees centigrade, said substantially constant flow rate has a mean value of between 0.3 and 10 m³/hr.
 23. Apparatus as claimed in claim 20, wherein for steam in the temperature range between 150 and 160 degrees centigrade, said threshold value is a value between 8 kPa and 12 kPa.
 24. Apparatus as claimed in claim 19, wherein at least one production AICD is configured to permit flow of heated hydrocarbons and condensed water into a production tube but to restrict the flow of steam into the production tube.
 25. Apparatus as claimed in claim 24, wherein said at least one production AICD is configured so that in the event of steam from said steam injector tubes reaching the production AICD, the production AICD autonomously closes so that any steam entering the production tube via the production AICD is less than 5% by weight of the total fluid entering the production tube via the production AICD.
 26. An apparatus as claimed in claim 19, wherein at least some of said injector AICDs comprise a body defining a flow path through the AICD and defining a recess containing a movable valve body, arranged so that movement of fluid along said flow path causes the valve body to move by exploiting the Bernoulli effect thus controlling the flow of fluid along said flow path.
 27. An apparatus as claimed in claim 19, wherein at least some of said production AICDs comprise a body defining a flow path through the AICD and defining a recess containing a movable valve body, arranged so that movement of fluid along said flow path causes the valve body to move by exploiting the Bernoulli effect thus controlling the flow of fluid along said flow path.
 28. An apparatus as claimed in claim 26, wherein said valve body is a freely movable valve body.
 29. An apparatus as claimed in claim 19, wherein the injector AICDs of at least one of the steam injector tubes are configured to inject steam into said formation at substantially the same steam flow rate.
 30. An apparatus as claimed in claim 19, wherein the injector AICDs of at least one of the steam injector tubes are configured to inject steam into said formation at different steam flow rates so that appropriate flow rates can be used for different parts of said formation.
 31. An apparatus as claimed in claim 19, wherein said steam injector tubes are arranged to extend substantially horizontally.
 32. An apparatus as claimed in claim 19, wherein said production tubes are arranged to extend substantially horizontally.
 33. An apparatus as claimed in claim 19, wherein said geological formation is an oil sand.
 34. An apparatus as claimed in claim 19, wherein said hydrocarbons to be recovered are bitumen or heavy oil.
 35. An apparatus as claimed in claim 19, taking the form of a steam assisted gravity drainage, SAGD, system.
 36. A method for thermal recovery of hydrocarbons from a geological formation, the method comprising the steps of: a) providing a thermal hydrocarbon recovery apparatus as claimed in any preceding claim; b) injecting steam into said geological formation via said injector AICDs; c) collecting heated hydrocarbons in said production tubes via said production AICDs; and d) moving said hydrocarbons to the surface via said production tubes. 